A number of techniques exist for accessing organic matter (OM) maturity in shales. Rock-Eval pyrolysis is one of these techniques and consists of subjecting a small shale aliquot to a temperature cycle and monitoring the amount of gas-phase products evolving as a function of temperature. Typically, three generation events occur. The first event, S1, occurs as the sample is exposed to a temperature of 300° C. and consists of free hydrocarbons (gas and oil) that are volatilized. The second event, S2, occurs as the temperature increases to 550° C. at a rate of 25° C. per minute and consists of cracking non-volatile hydrocarbons, e.g. kerogen. The temperature at which this generation reaches a maximum, is called Tmax, and may be interpreted as a measure of the shale maturity. Tmax may also be influenced by other OM characteristics, for example, initial composition and catalytic association with various minerals. Typical ranges of Tmax for immature are 400-430° C., mature 435° C.-450° C. and over-mature 450° C. A large proportion of gas shales are over-mature, but Tmax is relevant for assessing the degree to which the shale is over-mature. The third event, S3, is a measure of the amount of carbon dioxide that is associated with hydrocarbon cracking and S3 is useful for estimating the oxygen content of OM.
A second technique for assessing OM maturity consists of observing the percentage of light reflected from a shale sample, Ro %, where the percentage is calibrated against a standard that reflects 100% of the light. OM macerals become more glass-like and therefore reflect more light with increasing maturity. Typical ranges of Ro % are as follows: depositional (immature)—0.2-0.7; oil producing (immature-mature)—0.7-1.2 and gas producing (mature to over-mature) 1.2<Ro %<5.0. This technique was originally devised for determining the rank of coal and may be tedious, subjective, and imprecise. Moreover, due to the absence of vitrinite-producing land plants before ca. 360 million years ago, this technique cannot be applied to gas shales of older provenance.
A technique for measuring the free gas content consists of measuring the high pressure, high temperature methane capacity of a shale by fitting successive measurements of gas uptake as a function of pressure with a Langmuir isotherm to quantify total gas and adsorbed gas, where the difference is the free gas. In general, employing the Langmuir isotherm implies that analysis gas chemisorbs on the solid. However, methane does not chemisorb on the material constituents of shale. In this regard, information obtained by applying the Langmuir analysis may not be representative. Measuring the high pressure, high temperature methane capacity is time consuming, cumbersome and necessitates high pressure, for example, reservoir pressure, rendering it unattractive for applications at the wellsite.